TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractDue to the complex nature of carbonate reservoirs, reservoir characterization often leaves many uncertainties. Finding the right balance between risks associated with these uncertainties and optimum stimulation makes acid fracturing and matrix acidizing treatments challenging. The stimulation objectives become even more difficult in highly slanted, layered, naturally fractured reservoirs exhibiting high permeability contrast. In this environment, adequate fluid diversion and leak-off control have always been the key design elements for stimulation. Achieving diversion and leak-off with a degree of control to make treatments applicable to a wide range of reservoir uncertainties presents challenges.A novel, polymer-free degradable diversion system has been in use for the last three years in the largest carbonate reservoirs of the world, namely the Khuff formation in Saudi Arabia's Ghawar field. The self-diverting fluid combines viscoelastic surfactant in HCl with degradable fiber technology. The fluid develops viscosity as the acid spends, while the fibers bridge across perforation tunnels and fissures to form a filter cake. Because the fibers completely degrade with time and the spent fluid breaks when it comes into contact with hydrocarbons or solvents during flowback, the fluid temporarily limits injectivity into thief zones without damaging the reservoir.More than 50 wells have been stimulated with this fluid system covering a wide range of single and multi-stage matrix acidizing and acid fracturing treatments. The controllable nature of diversion from well to well and on-the-fly adjustment capabilities of the fluid system have successfully ensured stimulation performance despite the uncertainties of carbonate reservoirs in Saudi Arabia. In essence, this novel fluid became the standard insurance policy for stimulation treatments of carbonate formations where the permeability models are inherently underestimating the contrast due to difficulties of placing natural fractures and quantifying their impact.

In acid stimulation treatments, acid will enter the most permeable or the least damaged zones. Most of the fluid will flow into the path of least resistance leaving large portions of the formation untreated. A critical factor to the success of an acid stimulation treatment is proper placement of acid so that all productive intervals are contacted by sufficient volumes of acid. The original stimulation fluid flow was altered to achieve uniform placement of treatment fluids during acid stimulation in candidate wells. Particle bridging technique utilizing self-degrading particulates of multiple grain sizes was utilized to achieve successful diversion and fluid placement across the entire interval of interest. Particle size distribution was calibrated for use with both near wellbore bridging across perforations and far field diversion inside wormholes and natural fractures. For self-degradable particulates to be successful as effective diverter, it should have accurate particle size distribution, therefore, a comprehensive well data analysis performed during design stage to recognize the opportunity for combination of far-field and near wellbore diversion systems for acid stimulation treatment. The combination of far-field and near wellbore self-degrading particulate diversion systems allowed the entire intervals to be treated evenly under matrix and fracture conditions, which is usually hard to achieve during acid stimulation treatments utilizing conventional chemical diversion systems, especially in cases where separate sets of perforations would need to be treated with a single stage. Evaluation of the diversion effectiveness was done by running temperature log immediately after the stimulation, which demonstrated satisfactory cool down effect across perforation intervals. This diversion technique was found to be more enhanced to effectively acid stimulate in high temperature carbonate reservoirs of Saudi Arabia. The utilization of self-degrading particulates of various grain sizes for far-field and near wellbore diversions during acid stimulation in high temperature carbonate reservoir was a unique approach and can be further optimized to resolve the challenges of multistage acid stimulation treatments.

For the past decade, Saudi Aramco has been successfully exploiting tight gas sandstone formations. These formations are routinely hydraulically fractured to enhance gas production, but as the development of the existing fields continues into deeper formations the exploration of new reservoirs emerges. New challenges are now being faced especially, considering that higher temperature is being encountered and the fracture fluids currently being used (based on borate crosslinker) are not stable enough to tackle the extreme conditions. Metal-crosslinked fracture fluids have long been the most popular class of high viscosity fracturing fluids. Primary fluids that are widely used are titanate and zirconate complexes of guar, hydroxypropyl guar (HPG), carboxymethyl hydroxypropyl guar (CMHPG), or carboxymethyl hydroxyethyl cellulose (CMHEC). Zirconium-delayed CMHPG are typically used for high temperature applications. These types of fluids provide high temperature stability with low polymer loading with the added benefit of salt compatibility. The proppant transport capabilities of the metal-crosslinked fluids are excellent. Zirconiumdelayed CMHPG fracture fluid is currently the preferred fluids due to its extraordinary stable characteristics for bottom-hole temperatures (BHTs) up to 375°F. This paper addresses the research, lab testing and successful application of a metal-crosslinked fluid used for fracturing operations of a high temperature (312 ~330 °F) tight gas reservoir in Saudi Arabia, with its post-treatment evaluation to optimally develop these reservoirs in harsh bottom-hole conditions.

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Many Khuff gas wells have been experiencing inorganic scale deposits: iron sulfide, iron oxides and calcium carbonate, which are causing weak production and poor wellbore accessibility. The scale problem requires a prompt solution to meet Saudi Aramco gas production objectives.The history of scale removal trials in Khuff gas wells in Saudi Arabia included the mechanical removal with Coiled Tubing (CT), and the chemical dissolution with acid and/or other scale dissolvers pumped through CT or bullheaded. All these methods failed to provide the expected outcome and some jobs resulted in major operational failures like stuck pipe, pinholes, H 2 S release at surface, and formation damage. As a result of these failures the descaling jobs were put on hold by Saudi Aramco many times between 2007 and 2010 with no significant progress made until the 2 nd half of 2010.A project was launched to establish an innovative descaling procedure aimed at a safe and effective scale removal. The integrated solution starts with the temporary isolation of the reservoir to eliminate gas and H 2 S returns at surface, enable a "closed system" cleanout with safe solid handling at low choke pressure, and minimum surface testing equipment. The second step is based on mechanical removal that eliminates long soaking time and/or H 2 S generation during chemical dissolution. For that, a high pressure jetting tool designed and proved to remove hard scale is deployed on CT. The critical step of scale cleanout to surface is optimized with the use of large outside diameter CT string and special high temperature gel to ensure efficient lift and eliminate the risk of stuck pipes. The major enhancement to this project is the ability to monitor in real-time bottom-hole pressure and temperature, annular solid concentration, and the high pressure jetting tool efficiency with a fiber optic enabled coiled tubing string. The whole process resulted in a controlled and optimized scale removal treatment.Multiple case histories are presented in this paper to demonstrate the successful implementation of the integrated solution, which is then selected as the only approved method for scale removal in Khuff gas wells.